Part 2 of a 3-part Series:
The new “tight”or “unconventional” oil and gas plays being discovered all over the world are so different from conventional production that independent reserve evaluators face new challenges when calculating reserves.
That was one of the findings that came out of a conversation I had with Doug Ashton, Vice President of AJM Petroleum Consultants in Calgary, Alberta. AJM is one of “The Big Four” reserve evaluation companies in Canada.
It’s the annual reserve reporting season for energy producers, where everyone has to say how much oil and gas they have found in the last 12 months, and what it cost to find it. Companies like AJM (and Sproule & Associates, GLJ Petroleum Consultants and McDaniel and Associates) are basically appraising the asset base of the company… and deciding what is economic at current energy prices. The reserve report is like the balance sheet.
This document is so important I wanted Doug to help me understand how the independent firms like AJM estimate (because that’s what it is) how much oil and gas a company has in the ground.
And one very interesting thing that came up was how the new tight sand or shale plays – which is what many of the junior and intermediate producers are chasing when they talk about ‘resource plays’ – are creating challenges for reserve evaluators.
That’s because the average well profile on resource plays is so different than conventional wells. The dynamic duo technologies of horizontal drilling (HD) and multi-stage fracking (MSF) are used to create a lot more contact between the well bore and the oil/gas formation. This often makes for a higher Initial Production (IP) rate than conventional wells in western Canada.
But history is showing that those IP rates fall off quickly – that’s called the decline rate. The decline rate on tight plays is initially very steep and then flattens, while most conventional wells exhibit a more stable decline throughout their entire life. Everything is so different with resource plays that they present a challenge to reserve evaluators.
“For these (tight) resource plays there are not a lot of analogies out there,” Ashton says. “You’re trying to build a “type” well with data that’s less than 4-5 years old. In a reservoir with low permeabilityPockets are not connected, it may take 4-5 years to get a stabilized flow rate, so it makes it difficult use the result of other wells to predict and estimate reserves.”
Investors forget that history is short on these plays. We all invest in tight oil/gas plays now, but HD & MSF have only been opening up tight sand and shale formations for 12 years, starting with the Barnett shale gas play in the late 1990s (and it’s not analogous to western Canadian plays). And it has really only been 4-5 years now since HD & MSF have gone wildly commercial in many different basins.
“So we try to be conservative in calculating reserves for resource plays,” Ashton continues. “That “conservative” word doesn’t always make our clients very happy – while both the evaluator and the client want the most realistic type well, sometimes it takes a bit of discussion to agree on what realistic looks like.
“There needs to be a lot of caution exercised by both the evaluator and the client. If the production on the producing wells doesn’t follow the type well, the proved undeveloped and probable reserves could be at risk of being mis-stated.”
I asked Doug to walk me through how reserve evaluators do their job each year for their junior clients:
“We start by going through all their ownership information to determine their working interest and other royalties. Companies in Canada are required to report their working interest share of recoverable reserves.
“Step Two is figuring out what the company’s operating costs have been in the past year. We use that to forecast future operating costs. By definition you can’t have a reserve unless it’s economic. If you have a producing well and ‘op costs’ have increased in the past year… it is possible that increase could render your reserves uneconomic.
“Step Three is figuring out reserves, which is the most time consuming part of our process. Early on in the life of wells and pools we use “volumetric assessment,” which is a lot of geological work, where we determine the geometry of the reservoir, net pay (thickness of reservoir-KS), porosity, water content, pressures and temperatures.
“We then use that data to calculate the Original Oil or Gas in Place volume and then, based on what we think are good analogies we build our type well and estimate a recovery factorPercentage of oil recoverable vs. what is the Oil Originally In Place for the reservoir – which ultimately should result in a reasonable production profile. This is our predominant evaluation method for unconventional reservoirs. We start our evaluation at the well level, then consolidate the results to the field level, and then the company level. We look at each individual well.”
I asked how much time the reserve evaluators are in the field checking out wells. He said they essentially spend 100% of their time in the office and that everything they need is shipped into the office electronically.
“The reality is that we’re working with data, so on-site visits, especially in Canada, don’t really add any value to the process. Some international clients want us to look at wells, often because the data isn’t as readily available, and we will do that if required,” says Ashton.
He added that each reservoir engineer uses their own price deck to determine what is economic – and these can vary, but not by a lot (to a regular investor like me).
Interestingly, these reports aren’t public documents. But the law – in Canada it’s called National Instrument 51-101 – says companies must disclose a lot of the information that is in the reserve report. Most companies summarize it in a press release. The hard-core investor can go to www.sedar.com, the regulatory electronic filing database for public companies in Canada, and find all the required-to-be-public data in the Annual Information Form (AIF).
I asked Doug what he would suggest that retail investors should look for in the press release that outlines the reserve report highlights.
There are different types of reserves, including
1. Proved developed non producing
2. Proved undeveloped
These reserves both need more capital to get into production and the companies have to disclose how much capital that requires, which is called “future development capital” or FDCFuture Development Costs. Sometimes – but not often – you will see a company add reserves but not add in the FDCFuture Development Costs. This can be tens of millions of dollars, so by not having it included, it could be misleading for investors.
Ashton added that investors should check what portion of proved reserves are in production vs undeveloped non producing. The higher percentage of reserves that are producing, the less risk there is – so if only 25% of reserves are producing then a lot more capital is needed, which is more risky.
But as an investor, I say the flip side to that is – the more undeveloped reserves, the more upside there is in the stock, which should be realized as those assets do get into production.
Either way, you get all the data from the reserve report.
- Keith Schaefer
Publisher, the Oil & Gas Investments Bulletin
Part III — The “Reserve Report” — How some junior heavy oil companies are benefiting greatly from these reserve reports… and how it can tip off investors to profits in the junior oil space.
Part 1: Using the ‘Recycle RatioA measure of a company's production efficiency based on its finding and development costs. Equation: Profit from each barrel produced / cost of finding the barrel of oil’ for O&G Investing
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